Integrated assessment of CO2-ECBM potential in Jharia Coalfield, India

Coalbed methane (CBM) production is effectively achieved by utilizing two processes, viz. primary and secondary recovery. In this paper, the primary recovery of CBM was studied using the adsorption isotherm while CO2-ECBM process for the secondary recovery was simulated with realistic parameters. The adsorption isotherm for CH4 was drawn up to the pressure of 1200 psi for four coal samples and Langmuir isotherm curves for both CH4 and CO2 was measured for one sample up to 2000 psi. The adsorption isotherm of four samples was further utilized for finding the primary recovery factor of methane, showing that the average primary recovery is ~ 54% with the highest recovery factor of ~ 76% for one sample. Hence, CO2-ECBM process could be further implemented to enhance gas recovery. Then, a 3D heterogeneous coalbed model at a depth of 3219 ft was constructed using the COMET3 simulator to demonstrate the potential of CO2-ECBM recovery technique. A concept of break-even time was introduced in this study for the comprehension of CO2-ECBM process. It is found that coalbed reservoirs may opt to implement this technology with economically sound recovery.


Material and methods
Sample collection preparation. Four coal samples have been retrieved from the exploratory borehole of Jharia coalfield. The sickle-shaped Jharia coalfield was formed during the Permian age comprasing with Talchir, Barren measures, Barakar and Raniganj formation. Jharia coalfield is one of the main coalbed methane fields in India (Fig. 1). Barakar formation is the primary coal-bearing formation in the Jahria coalfield, and near about 18 coal seams that are mainly low to medium volatile bituminous coal present in this formation 28 . Nevertheless, high volatile bituminous coal is also revealed in some places. Jharia coalfield contains an enormous amount of methane for potential commercial CBM production.
Soon after retrieving the samples from the borehole, they were sealed in the desorption canister for measuring the gas content. After taking out the samples from gas canister, samples were wrecked in half-inch pieces and mechanically broken using a jaw crusher. Samples were then brought to a hammer mill for the reduction in size down to the mesh size of 8 ASTM (~ 2.38 mm). A series of experimental steps were used to obtain the desired particle sizes for various analyses. The perquisite samples were ground and sieved to a mesh size of 60/70 to obtain an average particle diameter of 230 µm 30 . Samples for the proximate, ultimate and adsorption analysis were prepared according to the same mesh size, while for petrographic analysis, polished specimen was made using 20 mesh coal sample. The lithology of coal samples confirms that it belongs to shaly coal to bright coal. The details of the samples are shown in Table 1.
The gas content of the coal samples. The gas content of the coal samples was analyzed using the United States Bureau of Mines (USBM) direct method 31,32 . The 50 cm freshly drilled borehole sample was sealed into the canister, and desorbed gas content was measured using the water displacement method. The actual gas content (G) adds the lost, desorbed and residual gas content as revealed in Eq. (1) 33  www.nature.com/scientificreports/ where Q 1 , Q 2 and Q 3 are the lost, desorbed and residual gas in cc, while w (g) is the borehole sample weight. Figure 2 described the combined experimental set-up for collection and measurement of desorbed gas in field as well as in laboratory. The section including ABCD is used in the field for determination of desorbed gas immediately after retrieval of core from the well. The core was kept inside the canister D and the desorbed gas from the  www.nature.com/scientificreports/ core was stored in graduated sample bottle A (fixed with clamp), dipped in the saline water through a two-way valve C. Once the system is brought to the laboratory, the valve is opened to the burette E through valve C and finally stored in collector "E". For laboratory analysis, the gas samples can alsobe connected to sample collector A. The coalbed gas content by dry and ash-free basis (G daf ) is defined by Eq. (2). The gas/vapor including moisture is adsorbed on the active surface area of the coal. In presence of ash, the active surface is reduced. Methane and moisture are competitive to the adsorption sites. Hence, the CBM gas content is decreased with the increament in ash content and moisture content.
where a and m are the ash and moisture fraction of coal, respectively. Sample characterization. Proximate, ultimate and petrographic analyses were utilized for the characterization of the coal samples. The proximate analyses of the collected samples were carried out using the Advanced Research Instrument-Proximate Analyzer (APA-2) by following the standardASTM D3172-07a (2007). Ultimate analysis of coal was conducted using Elementar Vario MICRO cube (EL III CHNS analyzer) by following the standard ASTM D3176-89 (2002). ASTM standard (ASTM D2798-18, 2018) was utilized to measure the vitrinite reflectance of coal samples. Adsorption isotherm. Adsorption isotherm for the coal were obtained using the indigenous setup based on the manometric method. This experiment was carried out at the reservoir condition for correctly depicting the methane adsorption capacity of coal. The schematic diagram for the experiment is shown in Fig. 3. The volume of gas adsorbed at different pressure and temperature conditions were measured using this apparatus. The details of the schematics diagram are described in another published literature 30 .
The Langmuir equation was used to calculate the volume of pure gas adsorbed (V) at a particular pressure (P).
where P L and V L are the Langmuir pressure and volume, respectively.  www.nature.com/scientificreports/

Numerical modeling of CO 2 ECBM process
Modeling of CO 2 -ECBM process was carried out after studying the coal samples' geological and geochemical parameters. The coalbed model includes heterogeneity and anisotropy in coal, dual-porosity (microspores and macropores), gas diffusion by Fick's second law, Darcy's law for flow in cleats, preferential adsorption of CO 2 over CH 4 , shrinkage and swelling of coal, permeability changes due to CO 2 injection, and mixture adsorption using extended Langmuir model. COMET3 simulator was used for CO 2 -ECBM modeling of Jharia coalfield. The modeling was done for 3650 days, i.e. CBM was substituted by CO 2 for ten years.
Governing equations for the modeling study. The governing equations in the COMET3 simulator are described below 20,34 : Mass conservation equation for gas: Mass conservation equation for water: where b n (n = g or w) is the bulking factor for gas and water, γ n is the gradient, R sw is the solubility of the gas in water, φ is the porosity of coal, Z is the elevation, q n is the well sources term for gas and water, q m is the flow of gas in the matrix and M n is the mobility of gas and water. The adsorption-desorption of the mixture of CO 2 /CH 4 was described by the extended Langmuir equation, which gives the amount of a particular gas adsorbed (V i ) 35 .
where j indicates gas components (CH 4 or CO 2 ), n c is number of gas components, V Li and P Li are the Langmuir volume and pressure of component i, y i is free gas mole fraction of component i, and P is pressure, psia.
The flow of gas in the matrix is described with Fick's second law of diffusion: where q m is the flow of particular gas, V m is the element volume of the matrix, sorption time is τ i , and C i is the concentration of gas component i. The porosity and permeability equations of the gas used are the Advance Resource International (ARI) models 20 : www.nature.com/scientificreports/ where C p and C m are the pore and matrix shrinkage compressibility respectively; φ and φ 0 are the coal porosity and initial coal porosity respectively, P and P 0 are the reservoir pressure and initial reservoir pressure, C and C 0 are the reservoir concentration and initial reservoir concentration respectively, k is the permeability and k 0 is the initial permeability. Equation (9) is an empirical correlation based on the Kozeny-Carman equation with the exponent fitted to relate the permeability with porosity, which are measured from experiments. In our studies, we did not measure these values, the value of n in general ranges from 2 to 4.
Assumptions made for modeling. 1. The coalbed has no dipping angle with constant thickness 2. The coalbed reservoir temperature is uniform and constant 3. Darcy's law is followed for describing the flow through cleats and fractures 4. The Fick's second law gives the diffusion in the coal matrix 5. The pseudo-steady state condition exists within a finite-difference grid block 6. The grid or finite difference blocks of the model is homogeneous or sorption time is constant within a block The coalbed block model. The dimension of the coalbed block was chosen as 1000 ft × 1000 ft × 11 ft at a depth of 3219 ft with four production wells and one injection well. The production wells were selected as diagonally opposite with injection well at the center (Fig. 4). The main parameters are the Langmuir constants for both components, relative permeability curve, reservoir temperature, gas content, wellbore dimension, pore pressure, porosity, permeability, pore and matrix compressibility of coal. The model with two phases (gas-water), two components (CO 2 -CH 4 ), and dual porosity (micro and macropores) was chosen to simulate the CH 4 production by CO 2 injection. The total coal block area is 23 acres. The coalbed model was divided into 20 grids of 50 ft each in x and y direction while 1 grid of 11 ft in z-direction.
The well diameter of the injection and production wells were chosen as 8 inches with a tubing diameter of 5 inches. CO 2 was injected at the bottom of the model. Parameters for the model are tabulated in Table 2.

Results and discussions
Gas content of the coal samples. The gas content of the coal samples is shown in Table 3. The maximum coalbed gas content was found as 9.98 cc/g for sample GC #14. The gas content on the daf basis was also calculated.
Characterization of coal samples. Samples were characterized based on proximate analysis, ultimate analysis, and vitrinite reflectance. As per the standard ASTM D388-18 (2018) for classification of rank and Stach's coal rank chart, coal samples belong to low volatile to medium volatile bituminous coal 36 . The characteristics of coal samples are shown in Table 4.
Adsorption isotherm and primary recovery. The CBM adsorption isotherms for the four samples and their respective Langmuir parameters are shown in Fig. 5a-d. The Langmuir constants obtained through regression analysis by fitting the adsorption data with the Langmuir equation are shown in Table 5. The isotherm curves of the samples belong to Type I adsorption isotherm curve 37 .
The primary recovery of methane was found using the analogy described in our previous publication 31 . The primary recovery of methane was analyzed using the adsorption isotherm with the help of critical desorption pressure and gas content. The dewatering process also plays an important role in the primary recovery of methane 31 . The CBM recovery factors from these samples were calculated using Eq. (10) and are shown in Table 6. are shown in Fig. 6, and these curves were used in the simulation. Similarly, the water and gas relative permeability curves were also one of the essential parameters for simulating the CO 2 -ECBM process. Relative permeability controls the production performance of the CBM reservoir, and determination of realistic curves is challenging 38,39 . The relative permeability curves for gas and water at varying saturation levels used here are drawn using the Corey correlation based on the Corey capillary pressure model 40 , as shown in Fig. 7.
Matrix CO 2 and CH 4 concentration. CO 2 injected in coalbed dispersed from the center to the production wells at the corner of the block. Figure 8 reveals the CH 4 and CO 2 concentrations in coalbed grids with anisotropy and heterogeneity. Figure 8a shows the methane concentration at 0 day, i.e., before the injection, there is only methane in the coal matrix, and slowly it desorbs due to the displacement of CO 2 . After 3650 days, nearly all methane would be desorbed from the coal matrix, and high concentration of CO 2 is shown in the coal matrix of the selected coal block, as shown in Fig. 8b. The maximum displacement rate of methane is achieved after 87 days of injection, i.e., 452 MSCFD.  www.nature.com/scientificreports/ CH 4 and CO 2 production and injection analysis. Both CO 2 injection and CH 4 production started at the same time. Although the production wells are placed equidistant from the injection well, the anisotropic permeability of the coal results in the rough start of the CH 4 production of from the production wells 41 . The cumulative CO 2 injection in Fig. 9a is linear because injection rate was fixed. Totally 2.25 BSCF of CO 2 is required for injection till ten years. The cumulative CH 4 production shown in Fig. 9b indicates that the maximum cumulative production of CH 4 is achieved after ~ 700 days, due to the breakthrough of CO 2 in the production wells.  www.nature.com/scientificreports/    www.nature.com/scientificreports/ The very early breakthrough of the CO 2 is after ~ 274 days, as shown in Fig. 10a. After breakthrough, the CO 2 production linearly increases up to 3650 days. The breakthrough time was analyzed with methane and gas production rates, as shown in Fig. 10b. The point where the methane production rate and total gas production rate curves bifurcate would be the breakthrough time. The CO 2 production rate after ~ 554 days exceeds the CH 4 production rate. This point is designated as break-even time. After this time, the production of CH 4 should be critically analyzed as separation cost of CO 2 would be high. The shrinkage and swelling effect is also one of the leading causes of the depletion in CH 4 production rate 42,43 .
Total water and gas production. Dewatering is a crucial stage for CBM production in coalbed methane reservoirs. Some of the wells could produce water up to 2-3 years 44,45 . The dewatering is required to reach the critical desorption pressure, and more dewatering means that the methane recovery factor would be lower 9,46 . Thus, water production for the coalbed methane reservoiris critical for the CBM project economics. In this simulation, water production rate remains high (~ 50 BPD) for the first ~ 80 days and starts decreasing drastically (Fig. 11). The water production rate drops to ~ 10 BPD at the end of the first year, when total water production is around 14,000 BBLS. However, after ten years, i.e. at the end of this study, the water production rate of the water becomes almost 0 (~ 0.2 BPD), and the total water production is estimated to be ~ 18,000 BPD. It can be observed that after 55 days the total gas production rate surpasses the water production rate.

Conclusions
Primary recovery of coalbed methane requires dewatering to reduce the reservoir pressure to desorb methane gas from the coal matrix. CO 2 injection displaces methane and reduces the partial pressure of methane, and its adsorption on coal surface further removes adsorbed methane. The following conclusions can be drawn from this study: 1. Primary recovery on coal samples shows that more than 50% of methane can be extracted from the coalbed except for one sample. 2. Simulation case study showed that five years are required to desorb all the methane through CO 2 -ECBM, after that methane production rate drops to zero. 3. The maximum methane production rate can be achieved after 87 days, which is ~ 452 MSCFD. Meanwhile, the cumulative methane production reaches 15,308 MSCF. The CO 2 amount in the cumulative gas production becomes noticeable after one-year injection, i.e. ~ 1 MSCF. Nevertheless, the production rate of CO 2 at this point is 0.1 MSCFD. 4. Water production in the coalbed methane reservoir plays a crucial role in determining the overall project economy. Cumulative water production in this numerical case is continuous from the beginning and becomes constant (~ 17,000 BBLS) after four years of injection.
This integrated experimental and numerical study is valid and helpful for future implementation of the value adding CO 2 -ECBM process in the Jharia Coalfield, India. Before realizing this technology in the coalfield, more comparative studies on well types and patterns 47 , economic analysis and feasibility study must be carried out. www.nature.com/scientificreports/